The present disclosure relates generally to the field of petroleum reservoir formation and fluid identification, more particularly to a method of determining heavy oil volume, and even more particularly to a method of distinguishing movable and non-movable portions of heavy oil components from wireline logging.
The ability to detect and quantify very viscous or heavy oil in petroleum reservoirs becomes more and more important as the discovery of conventional oils becomes more and more difficult while the worldwide consumption of petroleum products increases. Therefore, exploration and production of petroleum from heavy oil fields are inevitable trends as there are more proven heavy and very viscous oils reserves in the world than that of conventional oils.
Nuclear magnetic resonance (NMR) is one of the logging techniques that is useful for underground formation evaluation and fluid identification. In principle, the capability of identifying and quantifying fluid phases in porous media by NMR techniques is based on the sensitivity of NMR measured quantities, such as signal amplitude, diffusivity, relaxation times, and some combination thereof. NMR signature for heavy oil is characterized by very low diffusivity and short relaxation time, and, in extremely heavy oil reservoirs such as tar, the relaxation time can be so short that the signal is substantially decayed even before an NMR logging tool can detect it. Because the apparent relaxation time for both heavy oil and bound water (such as clay-bound-water, for example) are dominated by intrinsic relaxation mechanism (defined as the combination of bulk and surface relaxation rates), there is a great uncertainty in distinguishing heavy oil and bound water using relaxation time methods, diffusion contrast-based methods, or a combination of both methods.
The bound water in formation rock generally consists of clay-bound-water (CBW) and capillary bound (or irreducible) water (BVI). Often these two types of bound water volumes do not have a sharp boundary to separate them on a T2 (transverse relaxation time) distribution, but it is generally true that CBW resides in smaller T2 than BVI on a T2 spectrum. When the formation contains heavy oil, CBW is less likely to be discernable from the heavy oil. On the other hand, there are other logging techniques that may be used to estimate the volume of CBW. For instance, the reading of GR (gamma ray) from GR logging, expressed in API (American Petroleum Institute), is often used as a CBW indicator.
NMR relaxation time for a single-component oil, such as hexane, exhibits a single or nearly-single exponential decay behavior. Crude oils contain many constituents having different carbon numbers and different molecular structures. Therefore the relaxation time for crude oil exhibits a broader distribution, and the distribution pattern often associates with the underlying crude oil constituents. The feature of constituent mixture in crude oil is not often characterized by downhole fluid-analyzing devices or by openhole logging. A single value of viscosity or specific gravity is usually inadequate to fully describe a system that is intrinsically multiple components in constituents.
The distribution of T2 is potentially useful for characterizing the crude oil constituents. So far, however, NMR applications for fluid identification usually took a different route. Instead of utilizing the rich information provided by an oil T2 spectrum, common practice is to reduce the distribution to a single value, often a geometric-mean T2. Then this single value is correlated to the oil viscosity. However, the correlation is a less reliable quantity for heavy oil characterization, especially for extra-heavy oils. Additionally, this approach has failed to utilize T2 distribution for providing the need information of fluid component analysis.
Viscosity is often a very useful parameter to describe a conventional crude oil because it is related to the flow properties that are essential to oil production. However, viscosity alone cannot fully describe a heavy oil flow property because heavy oil may contain more complicated molecules, such as asphaltenes, which may affect fluid flow in different manners, such as precipitation. Thus, the amount of asphaltene in crude oil affects the production and transportation of heavy oil from formation to wellhead to surface. If one can characterize the amount of asphaltenes in the logging stage, one can choose the optimal production method that minimizes the asphlatene deposition, thereby minimizing the formation damage and pipeline clogging.
Another method for identifying heavy oil involves actively or passively heating the formation and the fluids therein, then performing logging measurements at a temperature equilibrium state and at an artificially elevated state. Because T2 of heavy oil is significantly affected by temperature, while T2 of water in rock formations is much less affected by temperature, by determining whether there is a significant T2 upshift as temperature increases one would be able to detect the presence of heavy oil in the formation that is otherwise indistinguishable by a single-temperature-state measurement alone.
The name heavy oil comes from the fact that the density of the oil is high. In the refinery industry, heavy oil is defined as the fuel oil remaining after the lighter oils have been distilled off during the refining process. For reservoir engineering, heavy oil is a type of crude petroleum characterized by high viscosity and a high carbon-to-hydrogen ratio. It is usually difficult and costly to produce by conventional techniques. The exact viscosity range for heavy oils varies.
Conventional crude oil may be viewed as oil that flows naturally or that can be pumped without being heated or diluted. Crude oil is commonly classified as light, medium, heavy or extra heavy, referring to its gravity as measured on the American Petroleum Institute (API) Scale, which is measured in degrees. U.S. industry defines light crude oil as having an API gravity higher than 31.1°, medium oil as having an API gravity between 31.1° and 22.3°, heavy oil as having an API gravity between 22.3° and 10°, and extra heavy oil (such as bitumen, for example) as having an API gravity of less than 10°. Canada has only two classifications, light oil with an API gravity greater than 25.7° API, and heavy oil with an API gravity less than 25.7° API. In other locations, such as the Lloydminster area of Alberta and Saskatchewan in Canada, heavy oil has API gravities ranging from 9° to 18°, and from the oilsands deposits in the Athabasca area of Alberta, Canada, heavy oil in the form of bitumen has an API gravity of around 8°. From the foregoing, it will be appreciated that the definition of heavy oil depends on the location of the deposits, having API gravities of 22.3° to 10° API for U.S. heavy oil, less than 10° for U.S. extra heavy oil, 18° to 9° for Alberta heavy oil, and 8° for Athabasca oilsands heavy oil, for example.
Accordingly, and from a practical standpoint, it would be more useful to define heavy and extra heavy oil in less rigorous terms. For practical purposes, it would be useful to relate heavy and extra-heavy oil based on the ability of the crude oil or oil components to flow, rather than the API values, because the API value is defined at a standard temperature and pressure condition of 1 atm and 60 degree-C., while the heavy oil reservoirs may be at different conditions. Thus, the viscosity values and the recoverability of the oil at a reservoir head may be substantially different from the standard condition. As such, and as herein used, the terms heavy oil and extra-heavy oil are referred to in relation to NMR characteristics, with heavy oil being defined as a viscous oil that has an intrinsic relaxation time upper-limit of approximately 5° ms (milliseconds) at reservoir condition, and extra heavy oil as more viscous oil that has an intrinsic relaxation time upper-limit of approximately 10 ms. Because crude oil contains hydrocarbons having a distribution of carbon-to-hydrogen ratio and chemical structures, a distribution of relaxation time is observed. The faster relaxing components are generally related to more viscous components and are less-likely to be producible with conventional oil recovery methods. It should also be noted, however, that the recoverability is also affected by the reservoir pressure. Thus, and as a practical matter, it is preferable not to define a clear-cut dividing line between heavy and extra heavy oils.
While existing petroleum reservoir analysis methods may be suitable for their intended purpose, there remains, however, a need in the art for an improved analytical method of determining heavy oil volume, and of distinguishing movable and non-movable portions of heavy oil components within a petroleum reservoir.